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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
⌧ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended Sept. 30, 2007
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from to
Commission File Number: 001-31387
Northern States Power Company
(Exact name of registrant as specified in its charter)
Minnesota 41-1967505
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
414 Nicollet Mall, Minneapolis,
Minnesota 55401
(Address of principal executive (Zip Code)
offices)
Registrant’s telephone number, including area code (612) 330-5500
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ⌧ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See
definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Non-Accelerated Filer ⌧
Large Accelerated Filer Accelerated Filer
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
No ⌧
Yes
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class Outstanding at Oct. 29, 2007
Common Stock, $0.01 par value 1,000,000 shares
Northern States Power Co. (a Minnesota corporation) meets the conditions set forth in General Instruction H (1)(a) and (b) of
Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to
such Form 10-Q.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments
necessary to present fairly the financial position of NSP-Minnesota and its subsidiaries as of Sept. 30, 2007, and Dec. 31,
2006; the results of its operations for the three months and nine months ended Sept. 30, 2007 and 2006; and its cash flows for
the nine months ended Sept. 30, 2007 and 2006. Due to the seasonality of electric and natural gas sales of NSP-Minnesota,
interim results are not necessarily an appropriate base from which to project annual results.
1. Significant Accounting Policies
Except to the extent updated or described below, the significant accounting policies set forth in Note 1 to the consolidated
financial statements in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2006 appropriately
represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.
Income Taxes — Consistent with prior periods and upon adoption of Financial Accounting Standard Board (FASB)
Interpretation No. 48 – “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109”,
NSP-Minnesota records interest and penalties related to income taxes as interest charges in the Consolidated Statements of
Income.
Reclassifications — Certain amounts in the Consolidated Statements of Cash Flows have been reclassified from prior-period
presentation to conform to the 2007 presentation. The reclassifications reflect the presentation of unbilled revenues,
recoverable purchased natural gas and electric energy costs and regulatory assets and liabilities as separate items rather than
components of other assets and other liabilities within net cash provided by operating activities. In addition, activity related to
derivative transactions have been combined into net realized and unrealized hedging and derivative transactions. These
reclassifications did not affect total net cash provided by (used in) operating, investing or financing activities within the
Consolidated Statements of Cash Flows.
2. Recently Issued Accounting Pronouncements
Fair Value Measurements (Statement of Financial Accounting Standards (SFAS) 157) — In September 2006, the FASB
issued SFAS 157, which provides a single definition of fair value, together with a framework for measuring it, and requires
additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 also emphasizes that fair value is
a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active
markets. Fair value measurements are disclosed by level within that hierarchy. SFAS 157 is effective for financial statements
issued for fiscal years beginning after Nov. 15, 2007. NSP-Minnesota is evaluating the impact of SFAS 157 on its financial
condition and results of operations.
The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No.
115 (SFAS 159) — In February 2007, the FASB issued SFAS 159, which provides companies with an option to measure, at
specified election dates, many financial instruments and certain other items at fair value that are not currently measured at
fair value. A company that adopts SFAS 159 will report unrealized gains and losses on items, for which the fair value option
has been elected, in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure
requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar
types of assets and liabilities. This statement is effective for fiscal years beginning after Nov. 15, 2007. NSP-Minnesota is
evaluating the impact of SFAS 159 on its financial condition and results of operations.
3. Income Taxes
Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48) — In July 2006,
the FASB issued FIN 48, which prescribes how a company should recognize, measure, present and disclose uncertain tax
positions that the company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax
benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective
date. As required, NSP-Minnesota adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a
cumulative effect of a change in accounting principle. The cumulative effect of the change, which is reported as an
adjustment to the beginning balance of retained earnings, was not material. Following implementation, the ongoing
recognition of changes in measurement of uncertain tax positions will be reflected as a component of income tax expense.
NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated income tax returns. Xcel Energy has
been audited by the Internal Revenue Service (IRS) through tax year 2003, with a limited exception for 2003 research tax
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credits. The IRS commenced an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research
credits for 2003) in the third quarter of 2006, and that examination is anticipated to be complete by March 31, 2008. As of
Sept. 30, 2007, the IRS had not proposed any material adjustments to tax years 2003 through 2005. The statute of limitations
applicable to Xcel Energy’s 2000 through 2002 federal income tax returns expired as of June 30, 2007.
NSP-Minnesota is currently under examination by the state of Minnesota for years 1998 through 2000. No material
adjustments have been proposed as of Sept. 30, 2007. As of Sept. 30, 2007, NSP-Minnesota’s earliest open tax years in which
an audit can be initiated by state taxing authorities under applicable statutes of limitations is 1998.
The amount of unrecognized tax benefits was $22.5 million and $20.0 million on Jan. 1, 2007 and Sept. 30, 2007,
respectively. Of these amounts, $4.1 million and $1.7 million were offset against the tax benefits associated with net tax
credit carryovers as of Jan. 1, 2007 and Sept. 30, 2007, respectively.
Included in the unrecognized tax benefit balance was $5.5 million and $4.1 million of tax positions on Jan. 1, 2007 and Sept.
30, 2007, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax
benefit balance included $17.0 million and $15.9 million of tax positions on Jan. 1, 2007 and Sept. 30, 2007, respectively, for
which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A
change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the
taxing authority to an earlier period. The decrease in the unrecognized tax benefit balance of $5.9 million from July 1, 2007
to Sept. 30, 2007, was due to the addition of similar uncertain tax positions relating to third quarter activity and the resolution
of certain federal audit matters.
NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state
tax audits progress. However, at this time due to the nature of the audit process, it is not reasonably possible to estimate a
range of the possible change.
The interest expense liability related to unrecognized tax benefits on Jan. 1, 2007, was not material. The change in the interest
expense liability from Jan. 1, 2007, to Sept. 30, 2007, was not material. No amounts were accrued for penalties as of Sept. 30,
2007.
4. Rate Matters
Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)
Midwest Independent Transmission System Operator, Inc. (MISO) Long-Term Transmission Pricing — In October 2005,
MISO filed a proposed change to its Open Access Transmission and Energy Markets Tariff (TEMT) to regionalize future
cost recovery of certain high voltage transmission projects to be constructed for reliability improvements. The proposal,
called the Regional Expansion Criteria Benefits phase I (RECB I) proposal, would recover 20 percent of eligible reliability
transmission costs from all transmission service customers in the MISO 15 state region, with 80 percent recovered on a sub-
regional basis for projects 345 kilovolt (KV) and above. Projects above 100 KV but less than 345 KV will be recovered 100
percent on a sub-regional basis. The proposal would exclude certain projects that had been planned prior to the October 2005
filing, and would require new generators to fund 50 percent of the cost of network upgrades associated with their
interconnection. In February 2006, the FERC generally approved the RECB I proposal, but set the 20 percent limitation on
regionalization for additional proceedings. On Nov. 29, 2006, the FERC issued an order on upholding the February 2006
order and approving the 20 percent limitation. On Dec. 13, 2006, the Public Service Commission of Wisconsin (PSCW) filed
an appeal of the RECB I order. The appeal remains pending.
In addition, in October 2006, MISO filed additional changes to its TEMT to regionalize future recovery of certain economic
transmission projects (345 KV and above) constructed to provide access to lower cost generation supplies. The filing, known
as Regional Expansion Criteria Benefits phase II (RECB II), would provide regional recovery of 20 percent of the project
costs and sub-regional recovery of 80 percent, based on a benefits analysis. MISO proposed that the RECB II tariff be
effective April 1, 2007.
On March 15, 2007, the FERC issued orders separately upholding the Nov. 29, 2006 order, accepting the RECB I pricing
proposal, and approving most aspects of the RECB II proposal. Various parties filed requests for rehearing of the RECB II
order in April 2007.
Transmission service rates in the MISO region presently use a rate design in which the transmission cost depends on the
location of the load being served (referred to as “license plate” rates). Costs of existing transmission facilities are thus not
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regionalized. MISO and its transmission owners filed a successor rate methodology on Aug. 1, 2007, to be effective Feb. 1,
2008, as required by the 1998 agreement among transmission owners creating the MISO.
MISO and most vertically integrated transmission owners proposed to continue license plate rates for existing facilities. The
March 15, 2007 FERC orders regarding RECB I and RECB II also required MISO to re-examine the cost allocation for new
reliability improvements and economic projects in the Aug. 1, 2007 filing. MISO and most transmission owners proposed
continued use of RECB I and RECB II for new facilities. Certain parties proposed to modify RECB I and RECB II to
regionalize the cost of all new transmission facilities 345 KV and above. Interventions and comments regarding the Aug. 1,
2007 cost allocation filings were submitted on Sept. 17, 2007.
In addition, on Sept. 17, 2007, American Electric Power (AEP) filed a complaint asking FERC to order regionalized cost
recovery of certain existing 500 KV and 765 KV facilities located in the PJM Interconnection, Inc. (PJM), another Regional
Transmission Organization (RTO), and the cost of new facilities 345 KV and above in PJM and MISO, over both the PJM
and MISO regions effective Oct. 1, 2007. Interventions and protests to the AEP complaint will be filed by Oct. 29, 2007.
Proposals to regionalize transmission costs could shift the costs of transmission investments by Northern States Power Co., a
Minnesota corporation (NSP-Minnesota) and Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin), also a
wholly owned subsidiary of Xcel Energy, to other MISO transmission service customers, but would also shift the costs of
transmission investments of other participants in MISO or PJM to the combined systems of NSP-Minnesota and NSP-
Wisconsin, which are managed as an integrated system and jointly referred to as the NSP System. Xcel Energy has estimated
the regional rate design proposed by AEP for existing facilities would shift approximately $2.5 million in annual transmission
costs to the NSP System. The impact of the regionalization of future facilities would depend on the specific facilities placed
in service. NSP-Wisconsin and NSP-Minnesota intend to oppose certain aspects of the AEP proposal.
MISO Ancillary Services Market — On Sept. 14, 2007, MISO filed an application with FERC to establish a regional
ancillary services market (ASM), whereby MISO would provide bid-based-regulation and contingency operating reserve
markets as an expansion of the regionalized wholesale energy sales market. The ASM is proposed to be effective in June
2008. Xcel Energy generally supports implementation of the ASM, since it is expected to allow NSP System generation to be
used more efficiently because certain generation will not always need to be held in reserve, and the ASM is expected to
facilitate the operation of wind generation on the NSP System required to achieve state-mandated renewable energy supply
standards. The ASM proposal is pending FERC action.
Revenue Sufficiency Guarantee Charges — On April 25, 2006, the FERC issued an order determining that MISO had
incorrectly applied its TEMT regarding the application of the revenue sufficiency guarantee (RSG) charge to certain
transactions. The FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005. The RSG charges are
collected from MISO customers and paid to generators. On Oct. 26, 2006, the FERC issued an order granting rehearing in
part and reversed the prior ruling requiring MISO to issue retroactive refunds and ordered MISO to submit a compliance
filing to implement prospective changes.
On March 15, 2007, the FERC issued orders separately denying rehearing of the Oct. 26, 2006, order and rejecting certain
aspects of the MISO compliance filings submitted in November 2006. The FERC ordered MISO to submit a revised
compliance filing. As of Sept. 30, 2007, Xcel Energy has recorded an accrual of $1.8 million for this matter.
Five parties have filed separate Petitions for Review at the United States Court of Appeals for the District of Columbia
Circuit (“D.C. Circuit”) seeking judicial review of the FERC’s determinations of the allocation of RSG costs among MISO
market participants. Xcel Energy, on behalf of NSP-Minnesota and NSP-Wisconsin, has intervened in each of these
proceedings. On Aug. 16, 2007, the D.C. Circuit dismissed two of these Petitions for Review as incurably premature because
the relevant petitioners also had pending requests for rehearing before the FERC. The remaining appeals are currently being
held in abeyance subject to the resolution of the FERC proceedings.
On Aug. 10, 2007, Ameren Services Company (Ameren) and the Northern Indiana Public Service Company (NIPSCO) filed
a joint complaint against MISO at FERC, challenging the MISO’s current FERC-approved methodology for the recovery of
RSG costs. Subsequently, on Aug. 17, 2007 and Aug. 24, 2007, Great Lakes Utilities, Indiana Municipal Power Agency,
Missouri Joint Municipal Electric Utility Commission, Missouri River Energy Services, Prairie Power, Inc., Southern
Minnesota Municipal Power Agency and Wisconsin Public Power Inc. (collectively, Midwest TDUs), and Wabash Valley
Power Association, Inc. (Wabash), respectively, filed complaints at the FERC effectively adopting the substantive arguments
raised by Ameren and NIPSCO. The Midwest TDUs and Wabash explained that they filed their complaints to protect their
own interests in the event that the complaint filed by Ameren and NIPSCO was dismissed by the FERC. On behalf of NSP-
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Minnesota and NSP-Wisconsin, Xcel Energy has moved to intervene in each of these proceedings. All three of these
complaints are currently pending at FERC.
Pending and Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)
NSP-Minnesota Electric Rate Case — In November 2005, NSP-Minnesota requested an electric rate increase of $168
million or 8.05 percent. This increase was based on a requested 11 percent return on common equity (ROE), a projected
common equity to total capitalization ratio of 51.7 percent and a projected electric rate base of $3.2 billion. On Dec. 15, 2005,
the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006.
On Sept. 1, 2006, the MPUC issued a written order granting an electric revenue increase of approximately $131 million for
2006 based on an authorized ROE of 10.54 percent. The scheduled rate increase has been reduced in 2007 to $115 million to
reflect the return of Flint Hills Resources, a large industrial customer, to the NSP-Minnesota system. The MPUC Order
became effective in November 2006, and final rates were implemented on Feb. 1, 2007.
On March 13, 2007, a citizen intervenor submitted a brief asking that the Minnesota Court of Appeals remand to the MPUC
with direction to determine the correct amount of income tax collected in rates but not paid to taxing authorities, order the
refund or credit to ratepayers for taxes collected in rates but not paid, order the refund to ratepayers of the amount of interim
rates collected in January and February of 2006 in violation of the previous merger order and provide other equitable relief.
The citizen intervenor passed away on May 15, 2007. The estate has filed a request with the Minnesota Court of Appeals that
the appeal continue with the estate listed as the appellant. The Court of Appeals will hold a non-oral conference on the appeal
on Dec. 4, 2007. No oral argument will be heard, and the parties are not allowed to attend the conference. Unless an
extension is granted, a decision will be issued by the Court within ninety days from the date of the non-oral conference.
NSP-Minnesota Natural Gas Rate Case — In November 2006, NSP-Minnesota filed a request with the MPUC to increase
Minnesota natural gas rates by $18.5 million annually, which represented an increase of 2.4 percent. The request was based
on 11.0 percent ROE, a projected equity ratio of 51.98 percent and a natural gas rate base of $439 million. Interim rates,
subject to refund, were set at a $15.9 million increase and went into effect on Jan. 8, 2007.
On Aug. 16, 2007, the MPUC voted to approve a rate increase of approximately $11.9 million, based on an authorized ROE
of 9.71 percent and an equity ratio of 51.98 percent. The written order was issued on Sept. 10, 2007.
On Oct. 1, 2007, NSP-Minnesota sought rehearing on the ROE issue, asking that the MPUC award a higher return consistent
with precedent. The Minnesota Office of the Attorney General (MOAG) opposed this request. The MPUC has until Nov. 29,
2007, to reconsider its order, or NSP-Minnesota’s petition for rehearing will be deemed denied and the Sept. 10, 2007, order
will be final.
MISO Day 2 Market Cost Recovery — On Dec. 20, 2006, the MPUC issued an order ruling that NSP-Minnesota may
recover all MISO Day 2 costs, except Schedules 16 and 17 administrative charges, through its fuel clause adjustment (FCA)
effective April 1, 2005.
• NSP-Minnesota is refunding Schedule 16 and 17 costs recovered through the FCA in 2005 ($4.4 million) to customers
through the FCA in equal monthly installments beginning March 2007.
• NSP-Minnesota is recovering 50 percent of Schedule 16 and 17 costs starting in 2006 in the final rates established in the
2005 electric rate case.
• NSP-Minnesota is allowed to defer 100 percent of the Schedule 16 and 17 costs not included in rates for a three-year
period before starting the amortization.
• The MPUC ruling on Schedules 16 and 17 costs will have no impact on net income in 2007.
On April 9, 2007, the MOAG filed an appeal of the MPUC order to the Minnesota Court of Appeals. NSP-Minnesota and the
other affected utilities intervened in the appeal and filed briefs urging the court to uphold the MPUC order. The date for a
court decision in the appeal is not known.
Transmission Cost Recovery — In November 2006, the MPUC approved a Transmission Cost Recovery (TCR) rider
pursuant to 2005 legislation. The TCR mechanism would allow recovery of incremental transmission investments between
rate cases.
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On Oct. 27, 2006, NSP-Minnesota filed for approval of recovery of $14.7 million in 2007 under the TCR tariff. On March 8,
2007, the MPUC voted to approve the recommendation of the Minnesota Department of Commerce (MDOC) to allow
recovery of $11.5 million in 2007.
On Aug. 31, 2007, NSP-Minnesota filed for approval of recovery of $19.7 million in Minnesota retail electric rates in 2008
under the TCR tariff. The Aug. 31, 2007 filing is pending written comments and MPUC action.
On Feb. 28, 2007, NSP-Minnesota filed for South Dakota Public Utilities Commission (SDPUC) approval of a Transmission
Cost Recovery Rider (TCRR). NSP-Minnesota proposed to recover $0.8 million in transmission related costs in 2007 outside
a general rate case. The tariff proposal is pending SDPUC action.
On Sept. 28, 2007, NSP-Minnesota and NSP-Wisconsin jointly filed proposed changes to the MISO TEMT to modify the
wholesale formula transmission rate applicable to the NSP System to change from a historic test year to a forward-looking
test year and provide for current recovery of a return on construction work in progress (CWIP) on certain new transmission
investments. The proposed rate change would be effective Jan. 1, 2008. If approved by FERC, the change would not affect
2007 results, but would be expected to generate approximately $2.7 million of additional wholesale transmission service
revenues in 2008 and additional annual increases in future years as NSP-Minnesota and NSP-Wisconsin work to complete
their planned investment of approximately $1 billion in additional transmission plant by 2012. The filing is pending
intervenor comments and FERC action.
Renewable Energy Standard Rider – In June 2007, NSP-Minnesota filed an application for a new rate rider to recover the
costs associated with utility-owned projects implemented in compliance with the Renewable Energy Standard adopted by the
2007 Minnesota Legislature. The proposed rate adjustment would recover the costs associated with the Grand Meadow wind
farm, a 100-MW wind project proposed NSP-Minnesota. The rate rider would recover the 2008 revenue requirements
associated with the project of approximately $14.6 million. MPUC consideration of the certificate of need and site certificate
needed for the Grand Meadow project is expected before year-end. On Oct. 2, 2007, the MDOC filed comments
recommending approval of the certificate of need, and no party has filed opposing comments as of this time.
Fixed Bill Complaint — In January 2007, the MOAG filed a complaint with the MPUC regarding the fixed monthly gas
payment programs of NSP-Minnesota and another unaffiliated natural gas utility. This program generally allows customers to
elect a fixed monthly payment for natural gas service that will not change for one year regardless of changes in natural gas
costs or consumption due to weather. The complaint seeks termination of the program or modification, and seeks interim
relief that would allow customers to exit the program.
On July 16, 2007, the MPUC issued its order suspending the program until it determines it is in the public interest. Other
terms of the order include allowing low income housing energy assistance program customers to immediately exit the fixed
monthly gas payment program retroactive to the start of the current program year without incurring an exit fee. NSP-
Minnesota has filed to terminate the program after the current year, and is informing the appropriate customers of their ability
to exit the program. In addition, NSP-Minnesota was directed to attempt to resolve all stranded cost issues with the MOAG.
If a settlement with the MOAG was not reached, NSP-Minnesota could submit a proposal to the MPUC for resolution. A
settlement was not reached. On July 6, 2007, NSP-Minnesota filed its proposal to resolve the phase out of the program, which
includes allowing early exit to an identified group of customers whose actual usage varied significantly from that assumed in
the fixed bill quote and recovery of all stranded costs associated with both early termination of the program and the exit of
the affected low-income and low usage customers. The MOAG disputes recovery of stranded costs and recommends
continued investigation. This matter is still pending before the MPUC with a decision expected later this year. Xcel Energy
does not expect the complaint to have a material impact on the consolidated financial statements.
Mercury Cost Recovery — On Dec. 29, 2006, NSP-Minnesota requested approval of a Mercury Emissions Reduction Rider.
The request is designed to recover approximately $5.4 million during 2007 from Minnesota electric retail customers for costs
associated with implementing both the mercury and other environmental improvement portions of the Mercury Emissions
Reduction Act of 2006. It was the MDOC’s position that NSP-Minnesota must file the environmental improvement plans
required in compliance with the 2006 Mercury Reduction Act before this filing could be approved. NSP-Minnesota
subsequently withdrew the filing and obtained approval to accrue costs associated with its compliance with the 2006 Mercury
Reduction Act in a deferred account for potential future recovery.
Annual Automatic Adjustment Report for 2006 — On Sept. 2, 2006, NSP-Minnesota filed its annual automatic adjustment
report for the period from July 1, 2005 through June 30, 2006, which is the basis for the MPUC review of charges that flow
through the FCA mechanism. The MDOC filed comments on April 18, 2007 asserting that NSP-Minnesota had not
demonstrated the reasonableness of its cost assignment of certain market energy charges from the MISO Day 2 market
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between daily sales of excess generation and native energy needs. The MDOC indicated that NSP-Minnesota should provide
additional support for its methodology. NSP-Minnesota filed reply comments arguing the cost assignment is consistent with
the methodology approved in both a 2000 MPUC investigation of FCA cost allocations and the Dec. 20, 2006 MPUC order
authorizing FCA recovery of most MISO Day 2 charges. The MDOC filed reply comments on Oct. 19, 2007 indicating that
the cost assignment issues raised in initial comments have been resolved, but raising other issues. NSP-Minnesota anticipates
filing reply comments responding to the MDOC’s new recommendations. The 2006 annual automatic adjustment report is
pending final MPUC action.
Annual Automatic Adjustment Report for 2007 — On Sept. 4, 2007, NSP-Minnesota filed its annual automatic adjustment
report for the period from July 1, 2006 through June 30, 2007, which is the basis for the MPUC review of charges that flow
through the FCA mechanism. During that time period, $1.16 billion in fuel and purchased energy costs, including $384
million of MISO Day 2 energy market charges were recovered from customers. The 2007 annual automatic adjustment report
is pending MDOC comments and MPUC action.
Annual Review of Remaining Lives Depreciation Filing — On June 4, 2007, NSP-Minnesota recommended lengthening the
life of the Monticello nuclear plant by 20 years, effective as of Jan. 1, 2007 as well as certain other smaller life adjustments,
as part of its annual review of remaining lives depreciation filing.
On Sept. 20, 2007, the MPUC approved NSP-Minnesota’s remaining lives depreciation filing lengthening the life of the
Monticello nuclear plant by 20 years, effective as of Jan. 1, 2007, as well as certain other smaller life adjustments. These
adjustments, of approximately $31 million, have been reflected in NSP-Minnesota’s consolidated financial statements for the
quarter and period ended Sept. 30, 2007, as a reduction of depreciation expense The MPUC also approved an adjustment to
rate base to be used in the next electric rate case that will hold ratepayers indifferent to this change in remaining lives
between rate cases. NSP-Minnesota calculated the revenue requirement associated with this adjustment to be approximately
$1.4 - $2.8 million, depending on the timing of the next electric rate case. In addition, the lengthening of the remaining life
for the Monticello nuclear plant decreased the related asset retirement obligation by $121 million for the third quarter of
2007.
5. Commitments and Contingent Liabilities
Except as noted below, the circumstances set forth in Notes 10, 11 and 12 to the consolidated financial statements in NSP-
Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2006 and Note 4 to the consolidated financial
statements in this Quarterly Report on Form 10-Q appropriately represent, in all material respects, the current status of
commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear
incident and are incorporated herein by reference. The following include unresolved contingencies that are material to NSP-
Minnesota’s financial position.
Environmental Contingencies
NSP-Minnesota has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at
several sites. In many situations, NSP-Minnesota believes it will recover some portion of these costs through insurance
claims. Additionally, where applicable, NSP-Minnesota is pursuing, or intends to pursue, recovery from other potentially
responsible parties and through the rate regulatory process. New and changing federal and state environmental mandates can
also create added financial liabilities for NSP-Minnesota, which are normally recovered through the rate regulatory process.
To the extent any costs are not recovered through the options listed above, NSP-Minnesota would be required to recognize an
expense.
Site Remediation — NSP-Minnesota must pay all or a portion of the cost to remediate sites where past activities of NSP-
Minnesota and some other parties have caused environmental contamination. Environmental contingencies could arise from
various situations including the following categories of sites:
• The site of a former manufactured gas plant (MGP) operated by NSP-Minnesota’s predecessors; and
• Third party sites, such as landfills, to which NSP-Minnesota is alleged to be a potentially responsible party (PRP) that
sent hazardous materials and wastes.
NSP-Minnesota records a liability when enough information is obtained to develop an estimate of the cost of environmental
remediation and revises the estimate as information is received. The estimated remediation cost may vary materially.
To estimate the cost to remediate these sites, assumptions are made when facts are not fully known. For instance,
assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of
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alternative cleanup methods and pollution-control technologies, the period over which remediation will be performed and
paid for, changes in environmental remediation and pollution-control requirements, the potential effect of technological
improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.
Estimates are revised as facts become known. At Sept. 30, 2007, the liability for the cost of remediating these sites was
estimated to be $1.0 million, of which $0.3 million was considered to be a current liability. Some of the cost of remediation
may be recovered from:
• Insurance coverage;
• Other parties that have contributed to the contamination; and
• Customers.
Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been
determined. Estimates have been recorded for NSP-Minnesota’s future costs for these sites.
Third Party and Other Environmental Site Remediation
Asbestos Removal — Some of NSP-Minnesota’s facilities contain asbestos. Most asbestos will remain undisturbed until the
facilities that contain it are demolished or removed. NSP-Minnesota has recorded an estimate for final removal of the
asbestos as an asset retirement obligation. See additional discussion of asset retirement obligations in Note 11 of the NSP-
Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2006. It may be necessary to remove some asbestos to
perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is
immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction
projects or removal costs for demolition projects.
Other Environmental Requirements
Clean Air Interstate Rule — In March 2005, the Environmental Protection Agency (EPA) issued the Clean Air Interstate
Rule (CAIR) to further regulate sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions. The objective of CAIR is to cap
emissions of SO2 and NOx in the eastern United States, including Minnesota. CAIR addresses the transportation of fine
particulates, ozone and emission precursors to nonattainment downwind states. CAIR has a two-phase compliance schedule,
beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions. Under CAIR,
each affected state will be allocated an emissions budget for SO2 and NOx that will result in significant emission reductions.
It will be based on stringent emission controls and forms the basis for a cap-and-trade program. State emission budgets or
caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model
program, or they can propose another method, which the EPA would need to approve.
NSP- Minnesota has generating facilities that will be impacted by CAIR. On May 30, 2007, the Minnesota Pollution Control
Agency (MPCA) issued a notice for implementing CAIR. This notice stated that Minnesota will administer the CAIR and the
EPA’s Federal Implementation Plan. Preliminary estimates of capital expenditures associated with compliance with CAIR for
the NSP System (Minnesota and Wisconsin) range from $30 million to $40 million. To date NSP-Minnesota has spent $12.3
million on CAIR compliance.
While NSP-Minnesota expects to comply with the new rules through a combination of additional capital investments in
emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives. NSP-
Minnesota believes the cost of any required capital investment or allowance purchases will be recoverable from customers.
Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulates mercury
emissions from power plants for the first time. The EPA’s CAMR uses a national cap-and-trade system, where compliance
may be achieved by either adding mercury controls or purchasing allowances or a combination of both and is designed to
achieve a 70 percent reduction in mercury emissions. It affects all coal- and oil-fired generating units across the country that
are greater than 25 megawatts (MW). Compliance with this rule occurs in two phases, with the first phase beginning in 2010
and the second phase in 2018. States will be allocated mercury allowances based on coal type and their baseline heat input
relative to other states. Each electric generating unit will be allocated mercury allowances based on its percentage of total
coal heat input for the state. Similar to the CAIR, states can choose to implement an emissions reduction program based on
the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.
NSP-Minnesota currently estimates that it can comply through capital investments in emission controls or purchase of
emission “allowances” from other utilities making reductions on their systems. Estimating the cost of compliance with
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CAMR is difficult because technologies specifically designed for control of mercury are in the early stages of development
and there is no established market on which to base the cost of mercury allowances. NSP-Minnesota’s preliminary analysis
for phase I compliance suggests capital costs of approximately $22.7 million for the mercury control equipment and
continuous monitoring equipment at the A.S. King, Sherburne County (Sherco) and Black Dog generating facilities. The
analysis indicates increased operating and maintenance expenses of approximately $22.6 million, beginning in 2010.
Additional costs will be incurred to meet phase II requirements in 2018. To date NSP-Minnesota has spent $1.2 million on
mercury monitoring implementation.
Minnesota Mercury Legislation — On May 2, 2006, the Minnesota Legislature enacted the Mercury Emissions Reduction
Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury
emissions at certain power plants. For NSP-Minnesota, the Act covers units at the King and Sherco generating facilities.
Under the Act, NSP-Minnesota has installed, and will maintain and operate continuous mercury emission monitoring systems
or other monitoring methods approved by the MPCA. The information obtained will be used to establish a baseline from
which to measure mercury emission reductions. Mercury emission reduction plans must be filed by utilities by Dec. 31, 2007
(dry scrubbed units) and Dec. 31, 2009 (wet scrubbed units) that propose to implement technologies most likely to reduce
emissions by 90 percent. Implementation would occur by Dec. 31, 2009 for one of the dry scrubbed units, Dec. 31, 2010 for
the remaining dry scrubbed unit and Dec. 31, 2014 for wet scrubbed units. The cost of controls will be determined as part of
the engineering analysis portion of the mercury reduction plans and is currently estimated to range from $22.7 to $280.2
million for the mercury control and continuous monitoring equipment, with increased operating and maintenance expenses
estimated to range from approximately $22.6 million to $48.4 million. The lower values include costs to achieve a 50 percent
mercury reduction for Sherco units 1 and 2, beginning in 2010. The higher values include costs to try to achieve a 90 percent
mercury reduction for Sherco units 1 and 2, beginning in 2010 and escalating to 2013. The lower cost estimates are also
included above as part of the total cost estimate to comply with CAMR. Utilities subject to the Act may also submit plans to
address non-mercury pollutants subject to federal and state statutes and regulations, which became effective after Dec. 31,
2004. Cost recovery provisions of the Act also apply to these other environmental initiatives. On Sept. 15, 2006, NSP-
Minnesota filed a request with the MPUC for recovery of up to $6.3 million of certain environmental improvement costs that
are expected to be recoverable under the Act. On Jan. 11, 2007, the MPUC approved this request to defer these costs as a
regulatory asset with a cap of $6.3 million. To date NSP-Minnesota has spent $1.2 million on mercury monitoring
implementation.
Regional Haze Rules — On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rules. These
amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit
technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional
haze.
The EPA requires states to develop implementation plans to comply with BART by December 2007. NSP-Minnesota
submitted its BART alternatives analysis for Sherco units 1 and 2 on Oct. 26, 2006. The MPCA reviewed the BART analyses
for all units in Minnesota and determined that overall, compliance with CAIR is better than BART. At this time, the MPCA is
not requiring any BART specific controls that go beyond controls required for CAIR compliance.
Voluntary Capacity Upgrade and Emissions Reduction Filing — On Jan. 2, 2007, NSP-Minnesota submitted a filing to the
MPUC for a major emissions reduction project at Sherco Units 1, 2 and 3 to reduce emissions and expand capacity. The
preliminary projected cost of this project was estimated at $900 million and encompasses the higher value mercury control
costs discussed above in the Minnesota Mercury Legislation section. NSP-Minnesota’s investments are subject to MPUC
approval of a cost recovery mechanism. An updated regulatory filing detailing the proposed project is planned in the fourth
quarter of 2007.
Federal Clean Water Act — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to
assure that these structures reflect the “best technology available” for minimizing adverse environmental impacts. In July
2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants.
Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit challenging the
phase II rulemaking. On Jan. 25, 2007, the court issued its decision and remanded virtually every aspect of the rule to the
EPA for reconsideration. In June 2007, the EPA suspended the deadlines and referred any implementation to each state’s best
professional judgment until the EPA is able to fully respond to the court-ordered remands. As a result, the rule’s compliance
requirements and associated deadlines are currently unknown. It is not possible to provide an accurate estimate of the overall
cost of this rulemaking at this time due to the many uncertainties involved.
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Legal Contingencies
In the normal course of business, NSP-Minnesota is subject to claims and litigation arising from prior and current operations.
NSP-Minnesota is actively defending these matters and has recorded a liability related to the probable cost of settlement or
other disposition when it can be reasonably estimated.
Metropolitan Airports Commission vs. Northern States Power Company — On Dec. 30, 2004, the Metropolitan Airports
Commission (MAC) filed a complaint in Minnesota State District Court in Hennepin County asserting that NSP-Minnesota is
required to relocate facilities on MAC property at the expense of NSP-Minnesota. MAC claims that approximately $7.1
million charged by NSP-Minnesota over the past five years for relocation costs should be repaid. Both parties asserted cross
motions for partial summary judgment on a separate and less significant claim concerning legal obligations associated with
rent payments allegedly due and owing by NSP-Minnesota to MAC for the use of its property for a substation that serves
MAC. A hearing regarding these cross motions was held in January 2006. In February 2006, the court granted MAC’s motion
on this issue, finding that there was a valid lease and that the past course of action between the parties required NSP-
Minnesota to continue making rent payments. NSP-Minnesota had made rent payments for 45 years. Depositions of key
witnesses took place in February, March and April of 2006. The parties entered into settlement negotiations in May 2006, and
in August 2006 reached an oral settlement of the dispute. The final form of the settlement documents was agreed upon and
the settlement documents were executed in September 2007. The Court filed an order of dismissal on Oct. 15, 2007. The
settlement is not expected to have a material impact on NSP-Minnesota’s consolidated financial statements.
Siewert vs. Xcel Energy — Plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action against NSP-
Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in
the construction and maintenance of distribution systems; and failure to warn or adequately test such systems. Plaintiffs
allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-
Minnesota’s distribution system. Plaintiffs’ expert report on the economic damage to their dairy farm states that the total
present value of plaintiffs’ loss is $6.8 million. NSP-Minnesota denies all allegations and made motions to exclude the
testimony of plaintiffs’ experts. Both sides made motions for summary judgment, which were denied in September 2007,
except that plaintiffs’ trespass claims were dismissed. NSP-Minnesota filed a motion to certify questions for immediate
appellate review on Oct. 16, 2007, which is scheduled to be heard on Oct. 30, 2007. NSP-Minnesota has also petitioned the
Minnesota Court of Appeals for permission to appeal. The trial is scheduled to commence in January 2008.
Carbon Dioxide Emissions Lawsuit — On July 21, 2004, the attorneys general of eight states and New York City, as well as
several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five
utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions. Although NSP-Minnesota is not
named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a
material adverse effect on NSP-Minnesota. The other utilities include American Electric Power Co., Southern Co., Cinergy
Corp. and Tennessee Valley Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial
operations and coal- or natural gas-fired power plants. The lawsuits allege that CO2 emitted by each company is a public
nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not
demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In
October 2004, Xcel Energy and the other defendants filed a motion to dismiss the lawsuit. On Sept. 19, 2005, the judge
granted the motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the Second Circuit Court of Appeals. On
June 21, 2007 the Second Circuit Court of Appeals issued an order requesting the parties to file a letter brief regarding the
impact of the United States Supreme Court’s decision in Massachusetts v. EPA, 127 S.Ct. 1438 (April 2, 2007) on the issues
raised by the parties on appeal. Among other things, in its decision in Massachusetts v. EPA, the United States Supreme
Court held that CO2 emissions are a “ pollutant” subject to regulation by the EPA under the Clean Air Act. In response to the
request of the Second Circuit Court of Appeals, the defendant utilities filed a letter brief on July 6, 2007, stating the position
that the United States Supreme Court’s decision supports the arguments raised by the utilities on appeal. It is unknown when
the Second Circuit Court of Appeals will rule on the appeal.
Hoffman vs. Northern States Power Company — On March 15, 2006, a purported class action complaint was filed in
Minnesota State District Court in Hennepin County, on behalf of NSP-Minnesota’s residential customers in Minnesota, North
Dakota and South Dakota for alleged breach of a contractual obligation to maintain and inspect the points of connection
between NSP-Minnesota’s wires and customers’ homes within the meter box. Plaintiffs claim NSP-Minnesota’s alleged
breach results in an increased risk of fire and is in violation of tariffs on file with the MPUC. Plaintiffs seek injunctive relief
and damages in an amount equal to the value of inspections plaintiffs claim NSP-Minnesota was required to perform over the
past six years. NSP-Minnesota filed a motion for dismissal on the pleadings, which was heard on Aug. 16, 2006. In
November 2006, the court issued an order denying NSP-Minnesota’s motion. On Nov. 28, 2006, pursuant to a motion by
NSP-Minnesota, the court certified the issues raised in NSP-Minnesota’s original motion as important and doubtful. This
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certification permits NSP-Minnesota to file an appeal, and it has done so. Briefs have been filed, and oral arguments were
heard Oct. 24, 2007.
Comer vs. Xcel Energy Inc. et al. — On April 25, 2006, Xcel Energy received notice of a purported class action lawsuit filed
in U.S. District Court for the Southern District of Mississippi. Although NSP-Minnesota is not named as a party to this
litigation, if the litigation ultimately results in an unfavorable outcome for Xcel Energy, it could have a material adverse
effect on NSP-Minnesota. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as
defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive
capacity of Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal theories, including negligence, and
public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this
lawsuit is without merit and intends to vigorously defend itself against these claims. On July 19, 2006, Xcel Energy filed a
motion to dismiss the lawsuit in its entirety. On Aug.30, 2007, the court dismissed the lawsuit in its entirety against all
defendants on constitutional grounds. On Sept. 17, 2007, plaintiffs filed a notice of appeal to the Fifth Circuit.
Schiltgen vs. Northern States Power Co. et al. — In November 2006, a suit was filed against NSP-Minnesota and others in
the Minnesota State District Court in Washington County, alleging that negligence on the part of NSP-Minnesota and others
led to severe injuries when the plaintiff contacted an electrical distribution line while working with a portable grain auger.
The matter was settled at mediation on Oct. 9, 2007, and the settlement is not expected to have a material impact on NSP-
Minnesota’s consolidated financial statements.
Nuclear Waste Disposal Litigation - In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against
the United States requesting breach of contract damages for the United States Department of Energy’s (DOE) failure to begin
disposing of spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota. When the
matter went to trial in October 2006, NSP-Minnesota was claiming damages in excess of $100 million through Dec. 31,
2004. On Sept. 26, 2007, the court awarded NSP-Minnesota $116.5 million in damages. On Oct. 11, 2007 the DOE filed a
motion for reconsideration in which it asks the court to reverse several of its key findings. NSP-Minnesota has been given
until Nov. 13, 2007 to respond to the motion. The DOE has 60 days from Sept. 26, 2007, in which to file an appeal. Results
of the judgment will not be recorded in earnings until the regulatory treatment and amounts to be shared with rate payers has
been resolved. Given the uncertainty of a potential appeal and regulatory treatment by the various utility commissions, it is
unclear as to how much, if any, of this judgment will ultimately have a net impact on earnings.
On Aug. 15, 2007, NSP-Minnesota filed a second complaint against the DOE in the Court of Federal Claims, again claiming
breach of contract damages for the DOE’s continuing failure to abide by the terms of the contract. This lawsuit claims
damages for the period Jan. 1, 2005 through June 30, 2007, which includes costs associated with the storage of spent nuclear
fuel at Prairie Island and Monticello, as well as the costs of complying with state regulation relating to the storage of spent
nuclear fuel. The amount of such damages is expected to exceed $40 million. The government has asked for and received an
extension to file its answer, and its answer is now due Dec. 14, 2007.
6. Short-term Borrowings and Other Financing Instruments
As of Sept. 30, 2007, NSP-Minnesota had $144.7 million of short-term debt outstanding at a weighted average interest rate of
5.49 percent.
7. Long-term Borrowings and Other Financing Instruments
On June 26, 2007, NSP-Minnesota issued $350 million of 6.20 percent first mortgage bonds, series due July 1, 2037. NSP-
Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the
proceeds to the repayment of commercial paper.
On Aug. 1, 2007, NSP-Minnesota redeemed all of its outstanding 8.00 percent Notes, Series due 2042, at a redemption price
equal to 100 percent of the principal amount of the notes ($25.00), plus accrued and unpaid interest on the notes, if any, to the
redemption date.
On Aug. 29, 2007, NSP-Minnesota borrowed $200 million against its $500 million five-year unsecured credit facility. The
weighted average interest rate on the borrowing was 5.76 percent. The borrowing was repaid on Oct. 1, 2007.
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8. Derivative Valuation and Financial Impacts
NSP-Minnesota uses a number of different derivative instruments in connection with its utility commodity price, interest rate,
short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options.
All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS 133 -
”Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), are recorded at fair value. The
presentation of these derivative instruments is dependent on the designation of a qualifying hedging relationship. The
adjustment to fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current
earnings or as a regulatory balance.
NSP-Minnesota records the fair value of its derivative instruments in its Consolidated Balance Sheets as separate line items
identified as Derivative Instruments Valuation in both current and noncurrent assets and liabilities.
Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow
hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging
transactions that NSP-Minnesota is currently engaged in are discussed below.
Cash Flow Hedges
NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity
prices and interest rates.
As of Sept. 30, 2007, NSP-Minnesota had various commodity-related contracts designated as cash flow hedges extending
through May 2008. The fair value of these cash flow hedges is recorded in Other Comprehensive Income or deferred as a
regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. This could include
the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or gas purchased
for resale.
NSP-Minnesota enters into various instruments that effectively fix the interest payments on certain floating rate debt
obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative
instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments
is recorded as a component of Other Comprehensive Income.
As of Sept. 30, 2007, NSP-Minnesota had net gains of approximately $1.1 million in Accumulated Other Comprehensive
Income related to interest rate cash flow hedge contracts that it expects to recognize in earnings during the next 12 months.
Gains or losses on hedging transactions for the sales of energy or energy-related products are recorded as a component of
revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging
transactions for gas purchased for resale are recorded as a component of gas costs and interest rate hedging transactions are
recorded as a component of interest expense. NSP-Minnesota is allowed to recover in natural gas rates the costs of certain
financial instruments purchased to reduce commodity cost volatility. There was an immaterial amount of ineffectiveness in
the third quarter of 2007.
The impact of qualifying cash flow hedges on NSP-Minnesota’s Accumulated Other Comprehensive Income, included as a
component of common stockholder’s equity, are detailed in the following table:
Nine months ended Sept. 30,
(Millions of dollars) 2007 2006
Accumulated other comprehensive income related to cash flow hedges at Jan. 1......... $ 9.4 $ —
After-tax net unrealized gains related to derivatives accounted for as hedges............... 2.1 9.6
After-tax net realized gains on derivative transactions reclassified into earnings ......... (0.3) —
Accumulated other comprehensive income related to cash flow hedges at Sept. 30 ..... $ 11.2 $ 9.6
Derivatives Not Qualifying for Hedge Accounting
NSP-Minnesota enters into certain commodity-based derivative transactions, not included in trading operations, which do not
qualify for hedge accounting treatment. These derivative instruments are accounted for on a mark-to-market basis in
accordance with SFAS 133. The results of these transactions are reported in the Consolidated Statements of Income.
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NSP-Minnesota’s consolidated financial statements from the Sept. 28, 2007, transaction date. WEC was required to pay an
exit fee and surrender all of its equity interest in NMC upon exiting. The effect of this transaction was not material to the
financial position or the results of operations to NSP-Minnesota for the three and nine months ended Sept. 30, 2007 and
2006. NSP-Minnesota plans to reintegrate its nuclear operations into its generation operations and apply to the Nuclear
Regulatory Commission to transfer the nuclear operating licenses from NMC to NSP-Minnesota. The transfer of licenses is
expected to be completed in early 2008.
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in general instructions
H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the
results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced
disclosure format).
Forward-Looking Information
The following discussion and analysis by management focuses on those factors that had a material effect on the financial
condition and results of operations of NSP-Minnesota during the periods presented, or are expected to have a material impact
in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and notes.
Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are
forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements
are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,”
“objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary
materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to
update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include,
but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures
and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy
industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional
competition in the markets served by NSP-Minnesota; unusual weather; effects of geopolitical events, including war and acts
of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an
impact on rates or have an impact on asset operation or ownership; structures that affect the speed and degree to which
competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings,
settlements, investigations and claims; actions of accounting regulatory bodies; the items described under Factors Affecting
Results of Continuing Operations; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with
the SEC, including “Risk Factors” in Item 1A of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2006 and
Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept. 30, 2007.
Market Risks
NSP-Minnesota is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A
— Quantitative and Qualitative Disclosures About Market Risk in its Annual Report on Form 10-K for the year ended Dec.
31, 2006.
Commodity price and interest rate risks for NSP-Minnesota are mitigated in most jurisdictions due to cost-based rate
regulation. At Sept. 30, 2007, there were no material changes to the financial market risks that affect the quantitative and
qualitative disclosures presented as of Dec. 31, 2006.
NSP-Minnesota maintains trust funds, as required by the Nuclear Regulatory Commission, to fund certain costs of nuclear
decommissioning. Those investments are exposed to price fluctuations in equity markets and changes in interest rates.
However, because the costs of nuclear decommissioning are recovered through NSP-Minnesota rates, fluctuations in
investment fair value do not affect NSP-Minnesota’s consolidated results of operations.
RESULTS OF OPERATIONS
NSP-Minnesota’s net income was approximately $220.3 million for the first nine months of 2007, compared with
approximately $219.8 million for the first nine months of 2006.
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Non-Fuel Operating Expense and Other Costs
Other Operating and Maintenance Expenses — The following summarizes the components of the changes in other utility
operating and maintenance expense for the nine months ended Sept. 30:
(Millions of dollars) 2007 vs. 2006
Higher nuclear plant operation costs................................................. $ 10
Higher combustion/hydro costs ........................................................ 9
Higher conservation incentive program costs................................... 9
Higher uncollectible receivable costs ............................................... 5
Higher nuclear plant outage expenses............................................... 4
Higher materials and supplies costs.................................................. 1
Lower employee benefit costs .......................................................... (5)
Lower fleet costs............................................................................... (3)
Lower information technology costs ................................................ (2)
Other ................................................................................................. 4
Total increase in other operating and maintenance expense ......... $ 32
Depreciation and Amortization – Depreciation and amortization expense decreased by approximately $14.9 million, or 4.7
percent, for the first nine months of 2007, compared with the first nine months of 2006. Depreciation and amortization
expense typically increases 3-5 percent year over year because of increased property, plant and equipment expenditures. This
decrease for the first nine months of 2007 was primarily due to the MPUC approval of NSP-Minnesota’s remaining lives
depreciation filing lengthening the life of the Monticello nuclear plant by 20 years, effective as of Jan. 1, 2007, as well as
certain other smaller life adjustments. The adjustments from this order resulted in an approximate $31 million reduction of
depreciation expense. The completion of the upgrade to the King plant, which came on line July 15, 2007, increased
depreciation expense by $3.5 million. These two events when combined with the normal increase in depreciation expense
from increased property, plant and equipment expenditures for planned system expansion resulted in the $14.9 million
decrease for the year.
Interest Charges – Interest charges increased by approximately $15.6 million, or 12.7 percent, for 2007, compared with
2006. The increase was due higher average debt balances. In addition, interest expense increased due to the accrual during the
first nine months of 2007 for the Minnesota electric interim rate and wholesale margin ratepayer sharing refunds.
Allowance for funds used during construction, equity and debt (AFDC) – AFDC is a non-cash amount capitalized as a part
of construction costs representing the cost of financing the construction. Generally, these costs are recovered from customers,
in future rates, as the related property is depreciated. NSP-Minnesota’s MERP project consists of converting two coal-fueled
electric generating plants located in the Minneapolis - St. Paul metropolitan area to natural gas, and installing advanced
pollution control equipment at a third coal-fired plant. The first of these projects began operating in July 2007 with the
remaining two expected to begin operations by 2009. AFDC, resulting in part from these projects, increased by
approximately $4.5 million, or 18.8 percent for the first nine months of 2007, compared with the same period in 2006. The
increase was partially offset by the current recovery from customers of the financing costs related to MERP through a rate
rider, resulting in a lower recognition of AFDC.
Income taxes – Income tax expense increased by approximately $28.2 million for the first nine months of 2007 compared
with the first nine months of 2006. The increase in tax expense in 2007 was primarily due to an increase in pretax income and
an increase in the forecasted annual effective tax rate in 2007 and the reversal of a $9.8 million regulatory reserve in 2006.
The effective tax rate was 38.6 percent for the first nine months of 2007, compared with 33.4 percent for the same period in
2006. The increase in the effective tax rate was primarily due to an increase in the forecasted effective rate for 2007 as
compared to 2006 and the recognition of a tax benefit relating to the reversal of a regulatory reserve in 2006. Excluding this
benefit, the effective tax rate for the first nine months of 2006 would have been 36.3 percent.
Regulation
Summary of Recent Federal Regulatory Developments
The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at
wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-
Minnesota. State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail
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rates and environmental matters. In addition to the matters discussed below, see Note 4 to the consolidated financial
statements for a discussion of other regulatory matters.
FERC Rules Implementing Energy Policy Act of 2005 (Energy Act) — The Energy Act repealed the Public Utility Holding
Company Act of 1935 effective Feb. 8, 2006. In addition, the Energy Act required the FERC to conduct several rulemakings
to adopt new regulations to implement various aspects of the Energy Act. Since August 2005, the FERC has completed or
initiated proceedings to modify its regulations on a number of subjects. In addition to the previous disclosure in Item 1 of
NSP Minnesota’s Form 10-K for the year ended Dec. 31, 2006, the FERC issued final rules making certain reliability
standards mandatory and subject to potential financial penalties up to $1 million per day per violation for non-compliance
effective June 18, 2007.
While NSP-Minnesota cannot predict the ultimate impact the new regulations will have on its operations or financial results,
NSP-Minnesota is taking actions that are intended to comply with and implement these new rules and regulations as they
become effective.
The electric production and transmission system of NSP-Minnesota is managed as an integrated system with that of NSP-
Wisconsin, jointly referred to as the NSP System. On Sept. 18, 2007, portions of the NSP System and transmission systems
west and north of NSP-Minnesota briefly islanded from the rest of the Eastern Interconnection, as a result of a series of
transmission line outages. The initial transmission line outage appears to have occurred on the NSP-Minnesota transmission
system due to a failure of a 345 KV conductor during severe weather, and approximately 6,000 NSP-Wisconsin customers
temporarily lost power. The Midwest Reliability Organization (MRO), the NERC regional entity responsible for oversight of
the electric system reliability in the upper Midwest, including the NSP System, has initiated an independent incident analysis.
Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric
transmission services. FERC policy encourages utilities to turn over the functional control over their electric transmission
assets and the related responsibility for the sale of electric transmission services to a RTO. NSP-Minnesota is a member of
the MISO. Each RTO separately files regional transmission tariff rates for approval by the FERC. All members within that
RTO are then subjected to those rates.
On Feb. 15, 2007, the FERC issued final rules adopting revisions to its 1996 open access transmission rules. NSP-Minnesota
submitted the initial required revisions to its Open Access Transmission Tariff (OATT) on July 13, 2007 and Sept. 11, 2007,
as required.
In addition, in January 2007, the FERC issued interim and proposed rules to modify the current FERC rules governing the
functional separation of the NSP-Minnesota electric transmission function from the wholesale sales and marketing function.
The proposed rules are pending final FERC action.
While NSP-Minnesota cannot predict the ultimate impact the new regulations will have on its operations or financial results,
NSP-Minnesota is taking actions that are intended to comply with and implement these new rules and regulations as they
become effective.
Centralized Regional Wholesale Markets — FERC rules allow RTO’s to operate centralized regional wholesale energy
markets. The FERC approved the MISO to begin operation of a “Day 2” wholesale energy market on April 1, 2005. MISO
uses security constrained regional economic dispatch and congestion management using Locational Marginal Pricing (LMP)
and Financial Transmission Rights (FTRs). The Day 2 market is intended to provide more efficient generation dispatch over
the 15 state MISO region.
On Feb. 15, 2007, the MISO filed for FERC approval to establish a “Day 3” centralized regional wholesale ancillary services
market (ASM) in 2008. The ASM is intended to provide further efficiencies in generation dispatch by allowing for regional
regulation response and contingency reserve services through a bid-based market mechanism co-optimized with the Day 2
energy market. In addition, MISO would consolidate the operation of approximately 20 existing NERC approved balancing
authorities (the entity responsible for maintaining reliable operations for a defined geographic region) into a single regional
balancing authority. The ASM and balancing authority consolidation are expected to benefit NSP-Minnesota’s integrated
operation by reducing the total cost of intermittent generation resources such as wind energy. On June 21, 2007, the FERC
issued an order rejecting the ASM proposal as incomplete, as recommended by Xcel Energy. The FERC stated the ASM
could still be implemented in 2008.
On Sept. 14, 2007, MISO again filed for FERC approval to establish a regional ASM whereby MISO would provide bid-
based regulation response and contingency reserve markets co-optimized with the Day 2 energy market and provide for the
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consolidation of balancing authorities. The revised ASM is now proposed to be effective in June 2008. Xcel Energy generally
supports implementation of the ASM, because it will allow native NSP System generation to be used more efficiently, since
certain generation will not always need to be held in reserve, and the ASM is expected to facilitate the operation of
intermittent wind generation on the NSP System required to achieve state-mandated renewable energy supply standards.
Comments on the ASM proposal were filed on Oct. 15, 2007. The proposal is pending FERC action.
Market Based Rate Rules — On June 21, 2007, the FERC issued a final order amending its regulations governing its market-
based rate authorizations to electric utilities such as NSP-Minnesota. The FERC reemphasized its commitment to market-
based pricing, but is revising the tests it’s using to assess whether a utility has market power and has emphasized that it
intends to exercise greater oversight where it has market-based rate authorizations. NSP-Minnesota has been granted market-
based rate authority and will be subject to the new rule. NSP-Minnesota is presently analyzing the new rule.
Other Regulatory Matters
Excelsior Energy Inc. (Excelsior) — In December 2005, Excelsior, an independent energy developer, filed a power purchase
agreement with the MPUC seeking a declaration that NSP-Minnesota be compelled to enter into an agreement to purchase
the output from two integrated gas combined cycle (IGCC) plants to be located in northern Minnesota as part of the Mesaba
Energy Project. Excelsior filed this petition making claims pursuant to Minnesota statutes relating to an Innovative Energy
Project and Clean Energy Technology. NSP-Minnesota opposed the petition.
The MPUC referred this matter to a contested case hearing to act on Excelsior’s petition. The contested case proceeding
considered a 603 megawatt (MW) unit in phase I and a second 603 MW unit in phase II of the Mesaba Energy Project.
The MPUC issued its order on Aug. 30, 2007. In it, the MPUC found that:
• Excelsior Energy is an innovative energy project under the applicable statute,
• The terms and conditions of the proposed PPA are inconsistent with the public interest and are denied,
• Excelsior Energy and NSP-Minnesota should resume negotiations towards an acceptable PPA, with assistance from the
Minnesota Department of Commerce and the guidance provided by the order, and
• The MPUC will explore a state-wide market for the output of this project.
Both NSP-Minnesota and Excelsior Energy filed timely requests for rehearing or clarification of this decision, which are
pending before the MPUC. MPUC action is scheduled for Nov. 1, 2007.
Meanwhile, the administrative law judge (ALJ) issued a decision in Phase 2 of this proceeding, recommending denial of
Excelsior’s proposed PPA for a second IGCC project. Exceptions and replies have been filed. The MPUC is expected to take
up this matter before year-end.
Renewable Energy Standard — The 2007 Minnesota legislature adopted a Renewable Energy Standard requiring NSP-
Minnesota to acquire 30 percent of its energy requirements by 2020 from qualifying renewable sources, of which 25 percent
must be wind energy. The legislation allows all NSP-Minnesota renewable resources to count toward meeting the standard
and provides greater flexibility toward meeting the standard. Costs associated with complying with the standard are
recoverable through automatic recovery mechanisms.
Conservation and Demand-Side Management Legislation – The 2007 Minnesota legislature adopted a bill establishing a
statewide goal to reduce energy demand by 1.5 percent per year and fossil fuel use by 15 percent. The bill requires utilities to
propose conservation and demand-side management programs that achieve at least 1.0 percent per year reduction in energy
demand, subject to certain limitations regarding excessive costs for customers, threatened reliability or other negative
consequences. The bill also allows utilities to fund internal infrastructure changes that will contribute to lower energy use and
provides for cost recovery outside a rate case for such projects.
NSP-Minnesota Base Load Acquisition Proceeding — On Nov. 1, 2006, NSP-Minnesota filed a proposal with the MPUC
for a purchase of 375 MW of capacity and energy from Manitoba Hydro for the period 2015-2025 and the purchase of
380 MW of wind energy to fulfill the base load need identified in the 2004 resource plan. The proposal included a signed
term sheet with Manitoba Hydro and a process to acquire the wind energy. Alternative suppliers were entitled to submit
competing proposals to the MPUC by Dec. 18, 2006. An alternate supplier proposed a 375 MW share of a lignite plant
located in North Dakota and 380 MW of wind energy generation, with an option for Xcel Energy ownership in both
components. The MPUC referred the matter to a contested case proceeding. On July 20, 2007, NSP-Minnesota filed a
petition asking to suspend the proceeding until NSP-Minnesota can complete its analysis of the impact of the RES and
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conservation goals on its need for additional resources, as outlined in the Notice of Changed Circumstance in the Resource
Plan filed by NSP-Minnesota with the MPUC on July 20, 2007.
In September 2007, the MPUC approved NSP-Minnesota’s Notice of Changed Circumstance and required NSP-Minnesota to
file a new Resource Plan by Dec. 14, 2007. Following review of the filing and expiration of the notice and comment period,
the MPUC is expected to take up the matter of schedule for the base load proceeding.
Additional Base Load Capacity Projects for Sherco, Monticello and Prairie Island — NSP-Minnesota had committed to
file for necessary approvals for projects to increase the capacity and provide additional base load generation from its Sherco,
Monticello and Prairie Island generating facilities by Sept. 1, 2007. On July 20, 2007, NSP-Minnesota filed a Notice of
Changed Circumstance with the MPUC seeking to delay these proceedings until NSP-Minnesota can complete its analysis of
the impact of the Renewable Energy Standards and conservation goals on its need for additional resources. In September
2007, the MPUC approved the Notice of Changed Circumstance and directed NSP-Minnesota to file a new Resource Plan by
Dec. 14, 2007. NSP-Minnesota intends to file applications for appropriate certificates of needs for these projects, if
confirmed by the Resource Plan, in a timely manner with or around the time of the Resource Plan to allow for consideration
of the proposals using consistent data and assumptions.
NSP-Minnesota Transmission Certificates of Need — In December 2001, NSP-Minnesota proposed construction of various
transmission system upgrades for up to 825 MW of renewable energy generation (wind and biomass) being constructed in
southwest and western Minnesota. In March 2003, the MPUC granted four certificates of need to NSP-Minnesota, thereby
approving construction, subject to certain conditions.
The MPUC granted a routing permit for the first major transmission facilities in the development program in 2004. The
remaining routing permit proceedings were completed in 2005. NSP-Minnesota now expects to complete the transmission
construction in 2008 at a cost of approximately $230 million.
In late 2006, NSP-Minnesota filed applications for certificates of need with the MPUC for three additional transmission lines
in southwestern Minnesota and one in Chisago County, Minnesota. On Sept. 17, 2007, the MPUC issued a certificate of need
authorizing NSP-Minnesota to construct three new 115 KV transmission lines (totaling 35 to 50 miles) in southwestern
Minnesota to provide approximately 400 MW of incremental transmission delivery capacity for wind generation. The three
projects, including associated substations, are expected to cost $72.5 million. The MPUC order required NSP-Minnesota to
file required route permit applications by January 2008 and complete construction by Spring 2009. Evidentiary hearings
regarding the Chisago County, Minnesota project were held in September 2007. The MPUC is expected to rule on the
Chisago County project by late 2007 or early 2008. The project would be placed in service in 2010.
In addition, NSP-Minnesota and Great River Energy, on behalf of nine other regional transmission providers, filed a
certificate of need application on Aug. 17, 2007, for three 345 KV transmission lines serving Minnesota and parts of
surrounding states. As stated in the application, the three lines would include construction of approximately 700 miles of new
facilities at a cost of $1.4 to $1.7 billion, with construction to be completed in phases between 2011 and 2015. The
application put forth a potential ownership percentage of 36 to 72 percent for each of the three 345 KV projects for NSP-
Minnesota and NSP-Wisconsin (combined). The certificate of need application for a fourth (230 KV) project is expected to
be filed by year end 2007. Updated NSP-Minnesota and NSP-Wisconsin cost estimates are expected following the
negotiation of Project Agreements outlining the terms and conditions related to construction management, ownership,
operations and maintenance of these facilities.
FCA Investigation — In 2003, the MPUC opened an investigation to consider the continuing usefulness of the FCAs for
electric utilities in Minnesota. There was no further activity until the MPUC issued a notice for comments on April 5, 2007,
as to whether to continue the statewide investigation.
Pursuant to the notice, utilities in Minnesota, the MDOC and the OAG filed initial and reply comments on April 30, 2007 and
June 1, 2007, respectively. The utilities generally argued the 2003 investigation could be closed, with remaining issues
addressed in the separate investigation initiated by the Dec. 20, 2006 order in the MISO Day 2 cost recovery docket. The
MDOC filed comments seeking to continue the investigations. In response, the utilities filed additional comments on Sept.
28, 2007 that indicated a willingness to continue with the investigation and provide more information to both regulators and
customers regarding fuel and purchased power costs, plant outages, and other factors affecting fuel clause levels. Reply
comments are due in October 2007. The MPUC is then expected to decide whether to continue or close the 2003
investigation.
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Grand Meadow Wind Farm — In June 2007, NSP-Minnesota filed an application for a certificate of need for the Grand
Meadows wind farm, a 100-MW development to be located in southeast Minnesota. NSP-Minnesota began developing this
project pursuant to legislation adopted by the 2003 Minnesota legislature that provided the company the right to own 100
MWs of the 300 additional MWs of wind mandates required as part of its consideration of life extension at the Prairie Island
nuclear plant. The Grand Meadows project would be implemented under a build-own-transfer agreement between NSP-
Minnesota and enXco, a wind project developer. Total project costs are estimated to be approximately $200 million. In
October 2007, the MDOC recommended approval of the certificate of need; no other public comments were received on the
application. The MPUC is expected to take up this matter later this year. The application for a site permit, filed by enXco, is
still pending review by the MDOC and approval by the MPUC. If approved, construction is expected to start in early 2008.
Capital Structure Petition - NSP-Minnesota filed its regular annual capital structure petition with the MPUC on Oct. 16,
2007. NSP-Minnesota is requesting an order by Dec. 31, 2007, which will approve the request for ongoing security issuance
and increased capitalization. Although NSP-Minnesota may exceed its authorized capitalization in January 2008, NSP-
Minnesota has a 60-day contingency period to be outside of the current authorized parameters. See a discussion of the long-
term borrowings at Note 8 to the consolidated financial statements.
Item 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be
disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in Securities and Exchange Commission rules and forms. In addition, the
disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to
management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions
regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the
supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of
our disclosure controls and procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and
procedures are effective.
Internal Control Over Financial Reporting
No change in NSP-Minnesota’s internal control over financial reporting has occurred during the most recent fiscal quarter
that has materially affected, or is reasonably likely to materially affect, NSP-Minnesota’s internal control over financial
reporting.
Part II. OTHER INFORMATION
Item 1. Legal Proceedings
In the normal course of business, various lawsuits and claims have arisen against NSP-Minnesota. After consultation with
legal counsel, NSP-Minnesota has recorded an estimate of the probable cost of settlement or other disposition for such
matters. See Notes 4 and 5 of the Financial Statements in this Quarterly Report on Form 10-Q for further discussion of legal
proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by
reference. Reference also is made to Item 3 and Note 11 of NSP-Minnesota’s Annual Report on Form 10-K for the year
ended Dec. 31, 2006 for a description of certain legal proceedings presently pending.
Item 1A. Risk Factors
NSP-Minnesota’s risk factors are documented in Item 1A of Part I of its 2006 Annual Report on Form 10-K, which is
incorporated herein by reference. There have been no material changes to the risk factors.
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29.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized on Oct. 29, 2007.
Northern States Power Co. (a Minnesota corporation)
(Registrant)
/s/ TERESA S. MADDEN
Teresa S. Madden
Vice President and Controller
/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Chief Financial Officer
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30.
EXHIBIT 31.01
Certifications
I, David M. Sparby, certify that:
1. I have reviewed this report on Form 10-Q of Northern States Power Co. (a Minnesota corporation);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting;
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize
and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: Oct. 29, 2007
/s/ DAVID M. SPARBY
David M. Sparby
Executive Vice President, Acting President and Chief Executive Officer
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31.
I, Benjamin G.S. Fowke III, certify that:
1. I have reviewed this report on Form 10-Q of Northern States Power Co. (a Minnesota corporation);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting;
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or
persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize
and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in
the registrant’s internal control over financial reporting.
Date: Oct. 29, 2007
/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Chief Financial Officer
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32.
Exhibit 32.01
Officer Certification
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Northern States Power Company (NSP-Minnesota) on Form 10-Q for the quarter
ended Sept. 30, 2007, as filed with the Securities and Exchange Commission on the date hereof (Form 10-Q), each of the
undersigned officers of NSP-Minnesota certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:
(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act
of 1934; and
(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and
results of operations of NSP-Minnesota as of the dates and for the periods expressed in the Form 10-Q.
Date: Oct. 29, 2007
/s/ DAVID M. SPARBY
David M. Sparby
Executive Vice President, Acting President and Chief Executive Officer
/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Chief Financial Officer
The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the
Report or as a separate disclosure document.
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or
otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by
Section 906, has been provided to NSP-Minnesota and will be retained by NSP-Minnesota and furnished to the Securities and
Exchange Commission or its staff upon request.
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Exhibit 99.01
NSP-Minnesota Cautionary Factors
The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such
disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied
by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially
from those projected in the statement. Forward-looking statements are made in written documents and oral presentations of
NSP-Minnesota. These statements are based on management’s beliefs as well as assumptions and information currently
available to management. When used in NSP-Minnesota’s documents or oral presentations, the words “anticipate,”
“estimate,” “expect,” “projected,” objective,” “outlook,” “forecast,” “possible,” “potential” and similar expressions are
intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause NSP-Minnesota’s actual results to differ materially
from those contemplated in any forward-looking statements include, among others, the following:
• Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;
• The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the
U.S. economy or the risk of increased cost for insurance premiums, security and other items;
• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in
geographic areas where NSP-Minnesota has a financial interest;
• Customer business conditions, including demand for their products or services and supply of labor and materials used in
creating their products and services;
• Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the
SEC, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;
• Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, NSP-
Minnesota or any of its subsidiaries; or security ratings;
• Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related
damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or
natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments;
nuclear or environmental incidents; or electric transmission or gas pipeline constraints;
• Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with
union employees, or work stoppages;
• Increased competition in the utility industry or additional competition in the markets served by NSP-Minnesota;
• State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact
on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets;
industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of
investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new
pricing structure; and former customers entering the generation market;
• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values
established by regulators assigning environmental costs to each method of electricity generation when evaluating
generation resource options;
• Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;
• Social attitudes regarding the utility and power industries;
• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;
• Technological developments that result in competitive disadvantages and create the potential for impairment of existing
assets; and
• Risks associated with implementations of new technologies.
NSP-Minnesota undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of
new information, future events or otherwise. The foregoing review of factors should not be construed as exhaustive.
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